Many crude oils processed by refineries contain varying amounts of nitrogen and sulfur compounds. During the refining process, it frequently becomes necessary to remove such compounds because they impart undesired properties such as disagreeable odor, corrosivity, poor color, and the like, to salable products. In addition, the compounds may have deleterious effects in various catalytic refining processes applied to oils.
Various processes have been devised for removing the nitrogen and sulfur compounds from oils, one common process being treatment with hydrogen wherein the nitrogen and sulfur compounds are converted to ammonia (NH.sub.3) and hydrogen sulfide (H.sub.2 S). Such conversion is usually promoted by use of elevated temperatures and pressures in the presence of hydrogenation catalysts. Reactions of the nitrogen and sulfur compounds with hydrogen to form NH.sub.3 and H.sub.2 S can also occur in other processes such as thermal and catalytic cracking, reforming, and hydrocracking, which are not specifically designed for such purpose. There are thus produced various effluent gas streams containing NH.sub.3 and H.sub.2 S.
The removal of some NH.sub.3 and H.sub.2 S from such effluent streams may be accomplished by scrubbing with water, preferably at elevated pressure and low temperature. To obtain the desired extent of removal, however, it is often necessary to use a rather large amount of water so that a dilute aqueous solution of ammonia and H.sub.2 S is formed. With increasing urbanization and concentration of industrial complexes, the situation is rapidly developing where pollution of water near population centers with such compounds is not desirable. The refiner thus may be compelled to remove the NH.sub.3 and H.sub.2 S from such waters in, for example, a sour water stripper resulting in a need to then dispose of the resulting NH.sub.3 and H.sub.2 S vapor.
In many cases, it is desirable to use the hydrogen sulfide present in such mixtures as feed to a sulfur recovery operation; however, the presence of ammonia can give rise to complications. While processes exist which are capable of effecting separation of ammonia from hydrogen sulfide, such methods require a large capital investment and the operating costs are relatively high.
In conventional sulfur recovery operations in which the feed gas typically contains more than 50 mol percent hydrogen sulfide with no significant concentration of ammonia, all of the acid gas feed is introduced into a noncatalytic combustion zone or furnace together with enough oxygen ordinarily in the form of air to convert about one-third of the hydrogen sulfide into sulfur dioxide. If the conventional method just described is used in the case of ammonia-contaminated hydrogen sulfide streams, even when sufficient additional air to burn ammonia is added, the hydrogen sulfide present competes with the ammonia for the extra oxygen, resulting oftentimes in incomplete combustion of the ammonia. The presence of excessive concentrations of ammonia in the combustion products creates conditions downstream for the formation of ammonium salts, which tend to accumulate in the equipment as solid materials and may cause plugging in catalytic reactors, in the condenser tubes, the tail gas scrubber system, sulfur separator seal legs, and the like. The failure of oxygen to effect complete combustion was borne out in tests performed where ammonia was purposely added to the feed. In a plant test, ammonia was present in the feed to the extent of about 23 volume percent or 230,000 ppm (dry basis). A conversion of about 99.7% was achieved in the furnace and the effluent had an ammonia concentration of about 200 ppm. In a second case (a laboratory run in which the feed contained 15 volume percent (dry basis) NH.sub.3), the ammonia conversion exceeded 99.9% and the furnace effluent had an ammonia concentration of about 35 ppm.
We have found in the past that an improved method for handling a gas stream which contains ammonia in a conventional sulfur plant is to feed all of the ammonia-containing gas to the burner of the furnace together with a portion of ammonia-free acid gas, while the remaining ammonia-free acid gas is fed to a downstream point. See Canadian Pat. No. 928,043 (1973). This makes it possible to achieve ammonia conversions in a plant furnace as high as indicated above for the laboratory test. In plant units with this design which do not have tail gas clean-up units, the resulting ammonia at low concentration has passed through the condensers and catalyst beds and the accumulation of solid byproduct materials, if any, has not been great enough to cause problems.
Further, sulfur plants are also employed to process H.sub.2 S-containing gases from various types of industrial operations other than petroleum refining. Hydrogen sulfide from certain operations may contain nitrogen-containing compounds which can form ammonia in the sulfur plant noncatalytic combustion zone or thermal reactor. An example is the hydrogen sulfide which is recovered from coal gas, also known as coke-oven gas, which is formed from destructive distillation of bituminous coal. This gas often contains hydrogen cyanide (HCN) which is partially combusted in the thermal reactor but may be partially hydrolyzed therein to form gaseous ammonia. We have found that the combustion system can be designed to result in a high efficiency for combustion of HCN, with the ammonia concentration in the effluent being low enough that it does not cause a problem in the condensers and catalytic reactors of conventional sulfur plant; however, it may cause a problem in certain tail gas clean-up units.
In order to comply with the regulations of the Environmental Protection Agency, many sulfur plants now in operation or being designed employ some type of tail gas treating process to minimize the amount of sulfur compounds ultimately discharged into the atmosphere. One such treating process is known as the Cold Bed Adsorption (CBA) method. The CBA process is described in detail, for example, in U.S. Pat. No. 4,035,474. When NH.sub.3 is present in the feed stream to the sulfur plant, however, a certain amount of NH.sub.3 remains in the sulfur plant tail gas; i.e., the feed to the tail gas clean-up process, for example, the CBA unit. Ammonia present in the feed to the tail gas-clean up process can react with SO.sub.2 present to form, for example, ammonium sulfite which is adsorbed on the catalyst during the sulfur adsorption portion of the cycle. Later in the regeneration portion of the cycle when the catalyst is heated with regeneration gas to desorb sulfur, NH.sub.3 also is liberated. The liberated NH.sub.3 can return in the regeneration gas to pass through the second Claus reactor and thence to the low temperature reactor now in the sulfur adsorption mode, where it can be again adsorbed on the catalyst. Thus, the ammonia can be repetitively adsorbed on the first CBA catalyst bed, then desorbed from the first CBA bed but readsorbed on the second CBA bed, then desorbed from the second but readsorbed on the first in the next cycle, and so forth. Continued operation in this manner can eventually cause the accumulation of solid ammonium salts deposited on the catalyst to be excessive and result in deactivation and plugging of the catalyst.
Solutions for this problem have been provided, but improved and alternative methods are needed. For example, one process is described in U.S. Pat. No. 4,391,790, which periodically returns at least a portion of the regeneration effluent stream itself to an ammonia decomposition catalytic reactor or to an ammonia combustion zone for the purpose of decomposing the ammonia. However, the regeneration effluent stream has a relatively low concentration of ammonia, which can decrease the conversion efficiency and can increase the energy requirement or fuel consumption of an ammonia conversion process. Therefore, effective methods of enriching the ammonia concentration of the regeneration effluent stream are highly desirable.
Particularly desirable are such improved and alternative processes for plants utilizing the Claus reaction for the recovery of sulfur for treating acid gas streams containing ammonia and/or other nitrogen compounds. Such an improved and alternative process and apparatus are hereinafter described.